The present invention relates to methods of treating a subterranean formation, and, at least in some embodiments, to methods of strengthening fractures in subterranean formations having low inherent permeability that comprise tight gas, shales, clays, and/or coal beds.
Subterranean formations comprising tight gas, shales, clays, and/or coal beds generally have a low permeability. As used herein, the term “tight gas” refers to gas found in sedimentary rock that is cemented together so that flow rates are relatively very low. As used herein, the term “shale” refers to a sedimentary rock formed from the consolidation of fine clay and silt materials into laminated, thin bedding planes. As used herein, the term “clay” refers to a rock that may be comprised of, inter alia, one or more types of clay, including, but not limited to kaolinite, montmorillonite/smectite, illite, chlorite, and any mixture thereof. The clay content of the formations may be a single species of a clay mineral or several species, including the mixed-layer types of clay. As used herein, “coal bed” refers to a rock formation that may be comprised of, inter alia, one or more types of coal, including, but not limited to, peat, lignite, sub-bituminous coal, bituminous coal, anthracite, and graphite. Traditionally, these unconventional formations have been viewed as having non-productive rock by the petroleum industry because they are “tight” and have low permeability. The term “permeability” as used herein refers to the ability, or measurement of a rock's ability, to transmit immiscible fluids, typically measured in darcies or millidarcies. Formations that transmit these fluids readily, such as sandstones, are described as permeable and tend to have many large, well-connected pores. Impermeable formations, such as shales and siltstones, tend to be finer grained or of a mixed grain size, with smaller, fewer, or less interconnected pores. If a single immiscible fluid is present in a rock, its relative permeability is 1.0. Calculation of relative permeability allows for comparison of the different abilities of fluids to flow in the presence of each other, since the presence of more than one fluid generally inhibits flow. The relative differences are often categorized as high permeability or low permeability relative to a permeability of 1.0. Also, they require specialized drilling and completion technologies. Recently, however, there have been a number of significant natural gas discoveries in such formations, which in this economic climate, have warranted production.
Fractures are the primary conduit for the production of oil and gas. In these applications, most of the effective porosity may be limited to the fracture network within the formation, but some gas may have also been trapped in the formation matrix, the various layers of rock, or in the bedding planes. To make these types of formations economical, fracturing/stimulation treatments often are advisable to connect the natural microfractures in the formation as well as create new fractures. Creating or enhancing the conductivity of the formation should increase the production of gas from the formation. In other words, the more surface area that can be exposed within the formation through fracturing the formation, the better the economics and efficiency will be on a given well.
Fracturing such formations is typically accomplished by using linear or crosslinked gels or fresh or salt water fluids comprising a friction reduction additive. These water type fracturing treatments are often referred to as “slick water fracs.” In such treatments, often the primary objective is to create or connect a complex fracture network, sometimes called a dendritic network, so hydrocarbons may be transported from the reservoir to the well bore in economic quantities.
Problematic in these fractures and fracture networks is the closure/healing of these fractures and or partial or complete proppant embedment resulting from increased closure stress due to high draw down pressures during production as well as potential softening of the formation after exposure to the treatment fluids. Many shales and/or clays are reactive with fresh water, resulting in ion exchange and absorption of aqueous fluids leading to embrittlement of the rock in the formation. The term “embrittlement” and its derivatives as used herein refers to a process by which the properties of a material are changed through a chemical interaction such that a material that originally behaves in a ductile or plastic manner is transformed to a material that behaves in a more brittle manner. Additionally, such degradation may substantially decrease the stability of fractures in the formation, which may cause a decrease in the productivity of the well.
This degradation also leads to proppant embedment. Proppant embedment is believed to cause a reduction in fracture width and conductivity, and may be caused by a compression failure within the fracture. Unlike in well-consolidated formations, proppant embedment in these types of tight formations can be as high as several proppant-grain diameters, e.g., in weakly consolidated sandstones. FIG. 1 illustrates the proppant embedment phenomena. FIG. 2 is a computer screen image illustrating the phenomena. Proppant embedment can reduce fracture width from about 10% to about 60% or more, for example almost 100%, when there is a very low concentration of proppant in the fracture, with subsequent reduction in productivity from oil and gas wells. FIG. 3 illustrates a fracture having near 100% embedment. When this occurs, the pathway for hydrocarbons to the well bore may become obstructed, and production may be impaired.
Clays can swell, disperse, disintegrate or otherwise become disrupted in the presence of foreign aqueous fluids. The swelling or dispersion of clays can significantly reduce the permeability of a formation. The use of salts as formation control additives has not eliminated formation damage as a result of permeability reduction, but can reduce or minimize such damage. A clay which swells is not limited to expanding lattice-type clays but includes all those clays which can increase in bulk volume with or without dispersing, degrading, or otherwise becoming disrupted, when placed in contact with foreign aqueous solutions such as water, and certain brines. Certain clays can also disperse, degrade, or otherwise become disrupted without swelling in the presence of foreign aqueous solutions such as water, certain brines, and emulsions containing water or certain brines. Some clays, in the presence of foreign aqueous solutions, will expand and be disrupted to the extent that they become unconsolidated and produce particles which migrate into a borehole. Formations which consist largely of clay upon absorbing water in a confined space can develop pressures on the order of several thousands of pounds per square inch.
The clay materials defined above occur as minute, plate-like, tube-like and/or fiber-like particles having an extremely large surface area as compared to an equivalent quantity of a granular material such as sand. This combination of small size and large surface area results in a high surface energy with attendant unusual surface properties and extreme affinity for surface-active agents. The structure of some of these clays, for example, montmorillonite, can be pictured as a stack of sheet-like three-layer lattice units which are weakly bonded to each other and which are expanded in the “c” crystallographic direction by water or other substances which can penetrate between the sheets and separate them.
Moreover, the fine aggregate that composes shales and/or clays can pose problems if exposed to high stresses. For example, under high stress, shale can mechanically fail, resulting in the generation of fine clay materials that can be highly mobile in produced fluids. In situations where there is high pore pressure and very little permeability, when the system is exposed to a low pressure environment, the surrounding formation can almost fluidize solid. For example, it is believed that shale, when exposed to high stress and pore pressure conditions, can transform from a solid into a semi-liquid material causing it to intrude into a proppant pack. This can result in shale intrusion, well bore sloughing and large quantities of solids production, plugging screens or filling separators on the surface.
In some formations, the bonding between bedding plane layers may be weaker than the bonding between particles in a given layer. In such formations, the bedding plane may represent a weakness susceptible to mechanical failure or separation. To combat these problems, brines are often used that contain high ion concentration so that ion exchange will not occur and the reactivity of the shales and/or clays will be reduced. In extreme cases, oil-based fluids may be used to avoid exposing the shales and/or clays to aqueous fluids.
Sloughing of shale sections has been an on-going problem for the petroleum industry for years. This sloughing has generally been attributed to shear failure occurring in the immediate well bore region when a circular hole is drilled into a rock under a particular stress state. Such rock formations may comprise laminated sands and/or layered sand/shale sequences.
As illustrated in FIG. 14, even very thin shale sections imbedded into a productive formation can undergo mechanical failure and result in significant solids being released into the formation. The presence of exposed shale in either of such systems represents significant risk to failure in many sand control completions in high permeability reservoirs. More specifically, the shale, when exposed to production pressure conditions with draw-down pressure, can undergo shear failure resulting in the liberation of formation fines that can damage and plug gravel packs and screens in sand control completions.
In open hole completions in a producing oil or gas well, exposed shale sections in the open hole section will be exposed to the reduced pressures required to initiate the flow of the oil or gas into the well. Since the shale typically has low permeability, it tends to trap pressure, potentially creating an imbalance where higher pressured shale formations exist in close proximity to low pressured productive formations. The fact that the shale traps pore pressure and is exposed to low well bore pressures causes an increase in stress, similar to drilling with a lightweight drilling fluid. This can lead to shear failure and bore hole break outs and sloughing of solids into the well bore.
FIGS. 12 through 17 show image logs taken in a well where borehole breakout occurred in the shale section. Borehole breakouts are zones of failure of the borehole wall which form symmetrically at the azimuth of the least principal horizontal stress. The breakouts are frequently elongated in the direction of the borehole axis, and can be described by three parameters: orientation in the borehole, opening angle, and radial depth. Borehole breakouts can result in drill string damage, borehole collapse, sand production, or loss of mud.
The use of aqueous-based drilling fluids are thought to exacerbate this problem as such fluids are thought to lead to swelling of the shale, causing its mechanical strength to be reduced and its susceptibility to shear failure, borehole breakout, and sloughing to be significantly increased.
In a stand alone screen completion, the liberation of solids from mechanically failed shale portions in the well bore can result in significant plugging or erosion of the screens ultimately leading to a completion failure due to lost productivity or sand production. Shale intrusion or embedment has also been identified as a problem in “FracPac™” type completions where there can be a significant loss in effective fracture width due to the invasion of solids into the high permeability proppant pack. In gravel pack and FracPac completions (collectively referred to herein as “pack completions”), the shale is still exposed to the reduced production pressures, but is supported mechanically by the presence of gravel or proppant. In certain shale formations, however, mechanical failure can result in extreme embedment where the proppant or gravel grains are pushed into the surface of the shale resulting in a loss in permeability in the gravel pack or proppant pack. In extreme cases where there is high differential pressure in the shale, this can behave more like an intrusion of the failed shale into the proppant pack as shown in FIGS. 1 and 2, for example.